Copyright 2003, Offshore Technology Conference This paper was prepared for presentation at the 2003 Offshore Technology Conference held in Houston, Texas, U.S.A., 5–8 May 2003. This paper was selected for presentation by an OTC Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Offshore Technology Conference or its officers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented.

Abstract This paper presents asset management concept and process and examples of sound reservoir management practice in developing a new field, revitalizing a mature old field, and developing a water flood project after primary depletion. Useful information is included about reservoir performance analysis and economic results for these example reservoirs at various stages of the reservoir life cycle. Introduction A reservoir’s life begins with exploration that leads to discovery, which is followed by delineation of the reservoir, development of the field, and production by primary, secondary, and tertiary means, and finally to abandonment (Figure 1). This Paper Presents:

• A brief review of asset management concepts and process.

• Examples of sound reservoir management practice used to enhance economics in projects at various stages of the reservoir life cycle:

o Development of a newly discovered offshore oil field.

o Revitalization of a mature offshore oil field. o Development of a water flood project.

Details of reservoir data, performance analysis techniques and results can be found in the published references 1, 2,3,4,5. Asset Management The ultimate goal of asset management is to maximize economic benefits from the company’s upstream, midstream, and downstream assets (Figures 2 and 3) by optimizing recovery while minimizing capital investments and operating costs. A sound management practice in upstream operation consists of setting goal, developing and implementing plan, monitoring

and evaluating performance, and revising necessary unworkable plans (Figure 4). This can be achieved by integration of multi-disciplinary professionals, technologies, tools, and data. This is a dynamic process throughout the reservoir life. Example 1 - Development of a Newly Discovered Offshore Oil Field. This example presents how a team of geoscientists and engineers developed an economically viable plan based upon an integrated reservoir model, reservoir performance analysis, and economic evaluation. Natural depletion or natural depletion augmented by water injection, and well spacing requiring the number of wells and platforms were considered. Reservoir Data. Rank Wildcat Well No. 1 was the example offshore oil field discovery well. The field is analogous to Gulf Coast reservoirs. Wells 2, 3, 4 and 5, were drilled to delineate the field (see Figure 5). A drill stem test was performed at the discovery well and the results indicated two productive zones at 4000 ft and 4500 ft depth. Initial production rates from the sand zones were 875 STBOPD and 1,456 STBOPD, respectively. Well No. 4 was a dry hole while Well No. 3 penetrated the oil-water contact. Preliminary data indicated that the under saturated reservoirs had good porosity, permeability, and contained light oil. This field had as much as 55 MMSTB of original oil-in place in the top layer and 102 MMSTB at the bottom layer. The field had a significant amount of potential reserves. Based upon permeability variation and to facilitate performance analysis, the upper sand was subdivided into two layers, while the lower sand was subdivided into three layers. Development and Depletion Strategy. An integrated geoscience and engineering team was charged to address the following main questions in order to come up with an economically viable development and depletion strategy:

• Recovery scheme - natural depletion or natural depletion augmented by fluid (water or gas) injection.

• Well spacing - number of wells, platforms, reserves

and economics To reach the goal, a full field reservoir simulation study was necessary to realistically forecast oil production rates and

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Asset Management through the Reservoir Life Cycle Abdus Satter

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reserves for various well spacing. The simulated production performance results were then used to economically optimize the number of wells and platforms. Reservoir Modeling. Considering 40, 80, 120, and 160-acre well spacings, a full-field reservoir simulation model was constructed to predict depletion drive performance. The model consisted of 30 columns, 23 rows and 3 layers in the lower sands and 2 layers in the upper sands. An impermeable layer separated the two sands. The reservoir layers were considered continuous and homogeneous throughout the field. In addition to the depletion runs, several runs were also made to investigate the effects of aquifer drive. An additional run was made using a 160-acre well spacing for initiating primary depletion, which was followed by 80-acre, 5-spot infill water flooding after two years. Water injection and production were initiated in the bottom sands, followed by operations in upper sands. Well production limitations included economic oil production rate of 30 MSTBPD, flowing bottom hole pressure of 600 psia, gas-oil ratio of 20,000 SCF/STB, and water cut of 95%. Production and Reserves Forecasts. The simulated primary performance results show that the larger spacing requires longer life with little effect on the ultimate primary recovery (Figure 6). The production performance for the water flood case is compared to the primary performance (Figure 7). The expected oil recovery from the water flood operation was more than double the primary recovery with a longer life. Facilities Planning. The simulated production performance results were used to size platforms, production decks and surface facilities, etc. Also, requirements for drilling, well completions and production practices were established. Subsequently, estimates of capital investments and operating expenses were made for economic analyses. Economic Optimization. Economic analyses of the primary and water flood development plans were made, using estimated production, capital, operating expenses, and other financial data. Results are shown in Table 1, which provided management several economic criteria to make their decision. The team’s recommendation was the initial 160-acre primary development followed by 80-acre, 5-spot infill water flooding after two years. Example 2 - Revitalization of a Mature Offshore Oil Field This example presents how integrated teams evaluated a mature offshore oil field performance and investigated various scenarios to add more value to the asset. Recommendations were made to add infill horizontal wells based upon oil saturation distributions from the reservoir simulation studies.

The team’s contribution to redevelopment plan resulted in more than doubling the booked reserves. The mature North Apoi/Funiwa Nigerian offshore Field was operated by Texaco (now Chevron Texaco) Overseas (Nigeria) Petroleum Company Unlimited (TOPCON). Multiple reservoirs, including the Ewinti and the Ala series have been producing for more than two decades. Due to declining production and uncertainty in the recovery efficiency, it was necessary to review performance of the field’s 6 largest reservoirs and recommend future direction. Integrated teams of geoscientists and engineers from TOPCON, Nigerian government organizations, and Texaco E & P Technology Department (EPDT) were charged in 1995 to make the studies in three phases. A different team made study in each phase. Table 2 shows multi-disciplinary professionals working on this project as an integrated team. The first phase study involving Ewinti-5, and Ala-3 reservoirs containing more than 50 % of the field’s booked reserves was initiated in March 1995 and completed in June 1995 in Houston at EPTD facilities. Subsequently, the second phase study, covering Ewinti-7 and Ala-5 reservoirs, and the third phase study, covering Ewinti-6 and Ala-7 were also carried out in Houston taking 3 months each. These integrated studies exemplify the close alignment between EPTD and TOPCON in the transfer and application of leading edge technologies in support of TOPCON’s growth plan. The results of this mature field studies are presented here. Objectives. The objectives of the studies were to determine ultimate primary recovery and optimum recovery with additional vertical and horizontal wells and workovers, including gas lift, and EOR potential. Challenges, Approach, and Deliverables. Challenges faced in the studies had to deal with mature reservoirs, declining production, increasing operating costs, unrealistic recovery factors and the need to enhance asset value. The approach taken was to review geoscience and engineering data, analyze past performance using classical material balance, decline curve, and reservoir simulation techniques. The expected deliverables included improved reservoir description, updated original oil-in-place, reserves additions, better reservoir management skills and strategies, and technology transfer from EPTD to TOPCON, followed by applications. Results. The studies utilized integration of multidisciplinary data, tools, and technologies, and professionals working together as a team.

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Integrated geoscience and engineering models were developed using revised maps based upon re-processed and re-interpreted 3-D seismic survey data of 1986. Well log and core analysis, rock and fluid properties, well test and other engineering data, and twenty years of field production history were also incorporated into the reservoir description. Decline Curve Analysis. Production Data Analysis module of Integrated Petroleum WorkBench software of Scientific Software Intercom (SSI), now owned by Baker Hughes Company, was used to make decline curve analysis of production data of wells, which had established declining production. The results compared favorably with the simulator-predicted results. Classical Material Balance. Classical material balance analysis was considered to be a pre-requisite to reservoir simulation. The EPTD-developed OILWAT material balance software was used for estimating original oil-in-place and primary drive mechanisms. The material balance analysis showed that the primary production mechanism of the Ewinti-5, Ewinti-7 and Ala-5 sands is influenced by strong water drive, with additional support from gas cap drive and solution gas drive. The Ala-3 reservoir demonstrates weak water drive plus gas cap and solution gas drive. Figure 8 shows the original-oil-in place estimated by classical material balance analysis and simulation techniques for the three phase studies. As shown, the results from both the material balance and simulation cases are comparable to each other, but are substantially greater than the booked values prior to this current study. The primary reason for the discrepancy was contributed to improved seismic data, defining larger reservoirs than previously mapped. Reservoir Simulation. SSI’s Black Oil Simulator was utilized for full-field performance history match and forecasts. The stepwise history matching procedure consisted of pressure matching, followed by saturation matching. Reasonably good history matches were achieved for most of the wells by adjusting the usual reservoir parameters within their accepted ranges of uncertainty. Some areas of poor seismic resolution had to be re-interpreted to determine fluid contacts, leading to successful history matches in all wells. After the reservoir performance history matching, prediction runs were made under various investment scenarios for optimally draining the reservoirs, including additional take points, horizontal wells, gas lift and water injection. Performance forecasts for the remaining period of the contract were made under different operating scenarios in order to determine the optimum development plan as follows: Case 1: Primary depletion with the current wells and production limitations (Do Nothing Base Case) Case 2: Base Case, Infill Wells and Workovers Case 3: Case 2 and Gas lift Case 4: Case 3 and Water Injection, applicable to Ala-3 Sand

Since the Ala-3 reservoir has weak natural water drive, the studies showed that recovery could be improved with water injection. The Ewinti-5, Ewinti-7 and Ala-5 reservoirs, on the other hand, have strong water drives, and thus no water injection case was attempted. The reserves increases which were estimated from the simulation studies are given in Figure 9. This figure shows reserves increases in millions of stock tank barrels involving the three phase studies under various production scenarios. The new estimated reserves are substantially more than the booked values. Each barrel represents several dollars per barrel profit margin to the company. Ten horizontal wells, 4 deviated wells, 1 replacement well and 4 workovers were recommended for the six reservoirs studied in three phases. All infill and workover wells are located in Finiwa field. The placement of the proposed horizontal wells was determined by examining the simulator-calculated oil saturation distributions initially and throughout the producing life of the reservoirs. For example, Figure 10 shows the oil saturation distributions for a selected layer in Ewinti-5. The end-of-lease base case (year 2008) shows significant remaining producible oil. Placing two horizontal wells at the current time and running the simulator to end-of-lease produced most of the recoverable oil. This study resulted in significant cycle time reduction and set an excellent example of integration and alliance. Within 9 months of the start of Phase 1 study, recommendation for two horizontal wells were quickly approved, drilled and completed in the Funiwa Ewinti-5 reservoir. The wells came on production as predicted, validating the results of the study. The first well initially produced 2,670 BPD of oil from a 700-foot horizontal section. The second well with a 1600-foot horizontal pay section produced 4,020 BOPD. Example 3 - Development of a Water flood Project This example presents how an integrated team developed an economically viable water flood plan for a synthetic primary depleted oil reservoir, considering peripheral and pattern floods with varying well spacing. A field, which was supposedly discovered many years ago, is now depleted. It consists of a simple domal structure and five of the nine wells drilled were producers (Figure 11). Primary producing mechanisms were fluid and rock expansion (reservoir pressure above the bubble point), solution gas drive and limited natural water drive. Data available are limited; even the gas, oil and water production data are unreliable. Reservoir pressures were not monitored. This is typical when dealing with old mature fields. An integrated team of geoscientists and engineers was charged by the management to review the past performance and

4 OTC 15082

investigate water flood potential of this field. The team’s approaches were to:

• Build an integrated geoscience and engineering model of the reservoir using available petrophysical and production data and correlations.

• Simulate full-field primary production performance

without history matching, since no historical pressure data were available.

• Forecast performance under peripheral and pattern

water flood.

• Finally, an economic evaluation of the development plan for each scenario to determine the preferred plan.

Even though the field is not real, much can be learned about how to engineer a water flood project even with incomplete data. Reservoir Data. An analysis of the logs from the nine wells showed that the reservoir heterogeneity could be represented by five producing horizons. Permeability was computed from a correlation of porosity vs. permeability. Permeability in the x and y directions were considered to be the same, i.e., no directional permeability. The vertical to horizontal permeability ratio was assumed to be 0.1. This under-saturated reservoir having the initial pressure several hundred psi above the 1855 psia bubble point, contains 33 o API crude oil at 2332 psia original reservoir pressure and 123 o F temperature. Fluid properties and gas-oil and water-oil relative permeability data were obtained from correlations, Production Performance. Using SSI’s Black Oil Simulator with 25x25x5 grids (3125 cells, with 1.02 acres each) a full-field reservoir simulation model was constructed to predict primary performance. The model used economic oil production rate of 10 STB/day, maximum gas-oil ratio of 5000 SCF/STBO, maximum water cut of 95 %, minimum bottom hole pressure of 150 psia, and top 3 layers being completed. The original oil, gas and water-in-place were computed to be 26.2 MMSTB, 10.8 BSCF and 19.1 MMSTB, respectively. Primary oil recovery was 4.1 MMSTB (15.7 % OOIP) after 8.3 years. Peripheral and pattern water flood development cases are shown in Figure 12. Performance forecasts for these cases were made in order to determine the optimum development plan. Figure 13 presents cumulative oil recovery due to primary and water flood production vs. time. Figure 14 shows water flood oil recovery vs. pore volume of injected water. Project life being the same, significantly higher recoveries are obtained in cases 2 and 5, which have more injectors and

producers than the others. Case 3 with only one producer shows the least recovery. Or in other words, recoveries are directly related to the number of production wells. Case 5 shows the least efficient recovery, considering water injection requirement. More oil recovery with more injection and production wells may not provide the best economically viable scheme. That can only be determined by economic analysis of the cases considered. Economic Evaluation. Making a sound business decision requires that the project be economically viable so as to generate profits satisfying the economic yardsticks of the company. The five water flood design cases were analyzed to determine the most economically viable project. The results of the economic analysis for these cases without considering federal income taxes are presented in Table 3, which gives management several economic criteria to make their decision. The analysis shows that all the cases are very favorable for water flooding. Case 3 gives the lowest amount of investment, reserves, and development costs and yet very favorable discounted cash flow return on investment, and the highest profit-to-investment-ratio. Case 2 for peripheral flood and Case 5 for pattern flood show the most promise. Case 5 shows the highest present worth net profit; however, this requires 80% more capital than for the Case 2, which gives about the same present worth net profit and better discounted cash flow return on investment. It should be realized that the recovery estimates for the Case 2 peripheral flood might be optimistic, because the reservoir layers were considered to be homogeneous and continuous. This may not represent the real situation. On the other hand, Case 5 for the pattern flood is better suited to treat reservoir heterogeneity and reservoir discontinuity. Conclusions Techniques presented in this work set good examples to develop a newly discovered field, revitalize a mature field, and develop an economically viable water flood project. Sound management process, integration of professionals, tools, technologies and data and multidisciplinary teamwork are essential for successful reservoir operations. References

1. Satter, A., Varnon, J. E., and Hoang, M. T. “Integrated Reservoir Management” JPT (Dec. 1994).

2. Satter, A., and Thakur G. C.: Integrated Reservoir

Management: A Team Approach, Penn Well Books, Tulsa, OK (1994).

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3. Akinlawon, Y., Nwosu, T., Satter, A. and Jespersen, R.: “Integrated Reservoir Management Doubles Nigerian Field Reserves”, Hart’s Petroleum Engineer International, (Oct. 1996).

4. Thakur, G. C. and Satter, A. Integrated Water flood

Asset Management, Penn Well Books, Tulsa, OK (1998).

5. Satter, A., Baldwin, J., and Jespersen, R. Computer-

Assisted Reservoir Management, PennWell Books, Tulsa, OK (2000).

Table 1 – Economic Evaluation Results of a New Field Development Plans

Parameters Primary Development Water Flood

Patterns, Acres 40 80 120 160 80

Investment, $MM 325 222 202 162 220

Reserves, MMSTBO 40.3 40.2 38.7 38.0 81.3

Economic Life, Years 9 11 15 15 22

Payout Time, Years 5.1 4.8 4.7 4.7 4.9

Discounted Cash Flow return on investment, % 29.0 38.8 35.8 40.4 42.7

Net Present Value, $MM 112 161 144 157 309

Present Worth Index 1.63 2.31 2.15 2.49 3.64

Development Costs, $ Per STBO 5.95 3.91 3.62 2.87 2.18

Table 2 – Integrated Reservoir Management Team

Organization

TOPCON 3 Engineers 1 Geologist 1 Geophysicist

Texaco EPTD Specialists 1 Geophysics 1 Computer Support 1 Geostatistics 2 Horizontal Wells 1 Petrophysics 1 Project Management 2 Reservoir Engineering

Nigerian Government 2 Engineers

Table 3 – Economic Evaluation Results of a Waterflood Project Development Plans

Parameters Primary Development

Water Flood

Case 1 2 3 4 5

Investment, $MM 1.85 4.88 0.97 3.48 8.80

Reserves, MMSTBO 1.97 5.14 1.38 3.18 5.11

Project Life, Years 15 15 15 15 15

Payout Time, Years 2.58 1.78 2.44 2.74 2.28

Discounted Cash Flow return on investment, % 69.6 131 80.1 87.8 105

Present Worth Net Profit, $MM 9.45 34.7 7.01 18.7 35.2

Profit to Investment Ratio 16.9 16.4 23.3 13.9 8.74

Present Worth Index 5.66 7.78 8.02 5.90 4.35

Development Costs, $ Per STBO 0.94 0.95 0.71 1.10 1.72

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Reservoir Life CycleDiscovery

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Figure 5 – Top Structure Map of a New Field - 4000 Foot Sand

Figure 6 - Effect of Well Spacing on Recovery

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Figure 8- Original Oil In Place for Three Phase Studies Figure 9 - Reserves Additions Summary for Three Phase Studies

Figure 10 – Oil Saturation Disribution on a Selected Layer

Figure 11 – Top Structure Map of a Waterflood Prospect Reservoir

Figure 12 – Waterflood Development Cases

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